1. Field of the Invention
The invention relates to the transportation of petroleum crude oil fluids.
The invention particularly relates to the pipeline transportation of petroleum crude oil containing one or more phases comprising liquid and gaseous hydrocarbons, water and solid phases including wax, ice and hydrocarbon hydrate slurries. The invention is especially related to a method, apparatus and composition for enhancing the pumpability of petroleum crude oil fluids having a high water volume rich in hydrocarbon hydrates.
2. Discussion of Background Information
This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present invention. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present invention. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
Oil and gas production facilities handle at least three phases including liquid hydrocarbon, gas and liquid water phases. Many facilities have to handle multiphase fluids that include additional solid phases such as wax, ice and hydrates. Hydrates can form rapidly in pipelines, causing large drifts of solid hydrate that reduce the flow of gas and liquids. The hydrates can be plowed up by the flowing liquids, causing the solids to completely block the pipeline with respect to liquid and gas flow. Once hydrate blockages occur, remediation options may include depressurization, hot liquid jetting via coiled tubing, bullheading thermodynamic inhibitors into the pipeline, electrical or natural heating or pipeline replacement. All of these remedies are economically costly and operationally hazardous.
There are many different solutions currently in use or known to prevent hydrate formation or manage hydrate pumpability. These include pipeline insulation, electrical heating, thermodynamic inhibitor (methanol and glycol) injection, kinetic inhibitor injection, anti-agglomerant chemical injection and hydrate slurry modification for cold flow. The term “inhibitors” refers to chemicals that prevent or retard hydrate formation while the term “anti-agglomerants” refers to surface active agents that restrict coalescence of formed hydrocarbon hydrates, promote the pumpability of formed hydrates and retard pipeline plugging by hydrocarbon hydrates. It is known in the art that the colder the pipeline fluid temperature, the more costly per barrel of hydrocarbon are the insulation, heating, thermodynamic and kinetic inhibitor treatment methods for hydrate remediation. It is known as well that the higher the percentage of water in the pipeline fluids, the higher the costs per barrel of hydrocarbon are for these same methods. Thus, colder fluid temperatures, particularly those below the temperature at which hydrates dissociate, favor anti-agglomerants and cold flow methods to avoid blockages in the pipeline. However, the effectiveness of both of these methods has been limited to a maximum of about 50 volume percent water to total liquids in the pipeline fluids. Above this maximum limit, the hydrate solids are not pumpable.
U.S. Patent publication number 2005/0137432 describes a method for inhibiting hydrate formation blockage in a flow line used to transport hydrocarbon containing fluids. Water is added to a hydrocarbon containing fluid to produce a water cut enhanced hydrocarbon containing fluid. Salt may be added to the hydrocarbon containing fluids as well. Hydrate formation blockage is said to be inhibited from forming within the flow line by the addition of the water and/or the salt, and that potentially toxic anti-agglomerate low dose hydrate inhibitors (“LDHI”) chemicals can be eliminated from offshore applications. The application of the disclosed method to heavy oils (approximately 20° API (American Petroleum Institute gravity)) is discussed. However, heavy oils typically have relatively low water-oil interfacial tensions and often contain significant quantities of polar compounds that can act as anti-agglomerants, with the result that hydrates do not plug or form blockages even in the absence of added anti-agglomerant. For lighter oils not containing such polar compounds, hydrate plugs or blockages may still occur.
Anti-agglomerant (“AA”) technology used today is in need of improvement in certain respects. While products for making pumpable hydrate slurries in fill wellstream flowlines are commercially available, current products are ineffective at water cuts above 50-60 volume percent water when used as directed. Most current products are ineffective at water cuts above 30-35 volume percent. The reason for the ineffectiveness at high water cut is believed to be that the anti-agglomerants cannot disperse water in oil as they do at lower water-cut. There is a phase inversion upon going from oil-water-anti-agglomerant at low water cut to high water cut. The hydrates formed in water-in-oil dispersions at low water cut are pumpable and non-plugging. The hydrates formed in oil-in-water dispersions at high water-cut are plugging as a rule. Hydrate slurries resulting from normal application of anti-agglomerants as known in the art at high water-cuts are too viscous to flow in a pipeline. The high viscosity occurs when the solid hydrate volume exceeds the liquid oil volume. Thus, there is a need for improved compositions, apparatus and methods for producing pumpable hydrocarbon hydrate pipeline slurries at high water cut. There is also a need for such improved compositions, apparatus and methods that are effective with lighter oils (greater than approximately 20° API).